In order to perform a 3D marine seismic survey, an array of seismic streamers, each typically several thousand meters long and containing arrays of seismic sensors (typically hydrophones) and associated electronic equipment distributed along its length, is towed at about 5 knots behind a seismic survey vessel, which also tows one or more seismic sources (typically air guns). Acoustic signals produced by the seismic sources are directed down through the water into the earth beneath and are reflected at interfaces where acoustic impedances of the differing geologic strata change. The reflected signals are received by the seismic sensors in the streamers, digitized and then transmitted to the seismic survey vessel, where they are recorded and at least partially processed with the ultimate aim of building up a representation of the earth strata in the area being surveyed.
Usually up to 12 streamers are towed, each of which is typically several kilometers long. The streamers are made up of sections that may be 100-200 meters in length; each section consists of hydrophones inside an outer skin that may be filled with oil, foam, or a more solid substance. Stress-wires and spacers form the internal skeleton of the streamer.
Marine seismic surveys are typically conducted to identify and characterize potential hydrocarbon deposits. The area being explored is generally subdivided into a number of cells or bins, using a gridding process. In 3D seismic surveys, these cells or bins are typically rectangular and have an in-line dimension (generally in the direction that the streamers are towed) and a cross-line dimension (generally perpendicular to the direction that the streamers are towed).
When designing a seismic survey, the resolution or granularity of the seismic image desired must be balanced against the cost of acquiring and processing the seismic data. If the same quantity of seismic data is acquired and processed for each bin, a seismic survey performed using a 12.5×12.5 meter bin size may cost up to 8 times more than a similar seismic survey performed using a 25×50 meter bin size. The parameter that quantifies the quantity of seismic data acquired for each bin is known as the “fold” of the seismic survey. Marine seismic surveys performed in connection with the exploration of a new geologic area or basin may have a relatively large bin size (such as 50×50 meters), while seismic surveys performed in connection with reservoir characterization or monitoring activities may have a relatively small bin size (such as 12.5×25 meters). Although some marine seismic data acquisition systems are able to acquire seismic data with in-line bin dimensions as small as 6.25 meters, the vast majority of seismic surveys are currently conducted with in-line bin dimensions of 12.5 meters or larger.
The seismic image of the subsurface will be contaminated or blurred by various types of noise in the seismic data acquired by the seismic sensors. In seismic data acquired by towed streamers, this noise can include ambient noise such as boundary layer turbulence, cross-flow noise and, in particular, swell noise and bulge wave (or breathing wave) noise. The main technique currently used to reduce this type of noise involves the creation of hydrophone groups by hardwiring series of adjacent hydrophones together to sum their respective analog output signals: typically a group contains between 6 and 12 uniformly-spaced hydrophones, and the centers of the groups are typically spaced at 6.25 meter or 12.5 meter intervals. Such an arrangement is disclosed in our U.S. Pat. No. 5,351,218, which also describes how pairs of adjacent groups can be selectively connected together to form groups of adjacent hydrophones whose group centers are spaced at 12.5 meter intervals.
Since the individual hydrophones in each group are fairly closely spaced, at approximately one meter apart on average, it is assumed that all the hydrophones in a given group receive substantially the same seismic signal. The seismic signal is therefore reinforced by the summing of the analog output signals of the hydrophones of the group, while the noise affecting each hydrophone, if it is randomly uncorrelated, will tend to be cancelled out by the summing process.
However, a great deal of the ambient noise in marine seismic data is not truly random in relation to the hydrophone groups of the prior art, so that the summing of the analog output signals of the hydrophones in each group is not effective at reducing it.
More sophisticated methods for attenuating noise in acquired seismic data are known. The best noise attenuation methods utilize filters having responses that vary in accordance with the spatial and/or temporal spectral content of the seismic data. A method using such filters is disclosed in our published PCT Patent Application No PCT/GB97/00055 entitled “Noise Filtering Method for Seismic Data”. While the filters utilized by these methods offer the greatest degree of noise attenuation while preserving the desired signal, they tend to be extremely CPU intensive, both to derive the filters and to apply them, and are therefore difficult and expensive to implement in the field (on the seismic vessel for instance).
One method that may be used to reduce the computational effort required to implement these types of noise attenuation methods utilizes the fact that the in-line bin dimension of the seismic survey is often significantly greater than the spatial separation intervals between the hydrophones or hardwired hydrophone groups used to acquire the seismic data. If, for instance, a streamer has hydrophone groups having group centers with 6.25 meter spatial sampling intervals and the in-line bin dimension of the seismic survey is 25 meters, the noise attenuation method may be applied in such a way as to produce noise attenuated seismic data having a spatial sampling interval that matches this desired in-line bin dimension. This type of selective application of the noise attenuation method (i.e. producing filtered output traces for each bin, rather than for each input trace) can result in a four-fold, or more, reduction in the computational effort required.
A different type of signal-related noise or perturbation (also sometimes referred to as ‘noise behind the signal’) that may be observed in marine seismic data (and other types of seismic data acquired using seismic sensors that move with respect to the subsurface) is known as the receiver motion effect. Many seismic data processing algorithms assume that the seismic data being processed is associated with a particular fixed seismic source point and a particular fixed seismic sensor (or receiver) point. This assumption is not met, however, when seismic data is acquired using towed streamers because the location of each of the sensors is constantly changing as the seismic data is acquired.
Often this spatial smearing effect is ignored, but it can be shown that (supposedly) adjacent 10 second records acquired using vessel sailing lines in opposite directions may contain seismic data associated with receiver points separated by up to 50 meters in the sailing line direction! Attempts have been made to correct for this receiver motion effect, such as through the use of the method described in our U.S. Pat. No. 5,050,129 (Schultz), issued Sep. 17, 1991 and entitled “Marine Seismic Data Conditioning”. As noted in this reference, the acquired seismic data can be transformed from a moving co-ordinate system to the fixed co-ordinate system of the earth by applying a time-variant spatial filter to the data.
Prior art streamer motion correction methods have suffered from various problems, however. First, as noted in Schultz, spatial aliasing can occur if the spatial sampling frequency is too coarse. If a seismic streamer acquires seismic data with relatively large absolute wavenumbers (larger than 1/25 m, for example) at a 12.5 m spatial sample interval (not frequency, which =1/12.5), then this data will be aliased and applying a time-variant spatial filter to motion correct the data will smear these signals. This problem will be substantially worse if the seismic data has a 25-meter spatial sampling frequency. Water multiples at far offsets may show apparent velocities of between 1500 and 3000 meters/second and the high frequency portions of this signal (between 60-120 Hz) may, for instance, show this aliasing problem. Second, it can be shown that a two-point linear interpolation method, such as described in Schultz, fails to properly reduce the level of signal error in the passband frequencies caused by the receiver motion effect Third, these methods rely on proper attenuation of motion-independent ambient noise (such as swell noise and bulge-waves) by the sensor groups. If this noise is insufficiently attenuated, or happens to be very strong, it will be smeared along the streamer, contaminating the seismic signal ever further.
While effective noise attenuation and receiver motion correction are both desirable, the functional interaction between these processes must be carefully considered. If the seismic data is receiver motion corrected prior to being noise attenuated, the apparent source of the noise will be smeared and the noise attenuation method may be significantly less effective. If the noise attenuation method produces output data with a relatively large spatial sampling interval, receiver motion correcting the noise attenuated data may cause aliasing.
It is therefore an object of the present invention to provide an improved method for acquiring and processing seismic data.
An advantage of the present invention is that the digitized seismic data may be both effectively noise attenuated and transformed to a stationary receiver point coordinate system (i.e. receiver motion corrected).